Reactivated Hydroprocessing Catalysts for Use in Sulfur Abatement

ABSTRACT

Disclosed herein are methods, systems, and compositions for providing catalysts for tail gas clean up in sulfur recovery operations. Aspects of the disclosure involve obtaining catalyst that was used in a first process, which is not a tailgas treating process and then using the so-obtained catalyst in a tailgas treating process. For example, the catalyst may originally be a hydroprocessing catalyst. A beneficial aspect of the disclosed methods and systems is that the re-use of spent hydroprocessing catalyst reduces hazardous waste generation by operators from spent catalyst disposal. Ultimately, this helps reduce the environmental impact of the catalyst life cycle. The disclosed methods and systems also provide an economically attractive source of high-performance catalyst for tailgas treatment, which benefits the spent catalyst generator, the catalyst provider, and the catalyst consumer.

CROSS REFERENCE TO RELATED APPLICATIONS

This is a non-provisional of U.S. Provisional Patent Application Ser.No. 62/852,102, filed May 23, 2019, which is incorporated herein byreference in its entirety, and to which priority is claimed.

FIELD OF THE TECHNOLOGY

The present application relates to catalysts and processes for tailgastreatment in a hydrocarbon treating process. More specifically, theapplication relates to reactivating a catalyst used in a hydroprocessingprocess and using the reactivated catalyst for tailgas treatment.

BACKGROUND

The necessity of removing sulfur from hydrocarbon streams, such as oiland natural gas derivative streams, for pollution control is well known.If sulfur is not removed from hydrocarbon compounds, then, uponcombustion, sulfur dioxide and sulfur trioxide will be formed. Thesecompounds can react with moisture in the atmosphere to form sulfuricacid, a contributor to the phenomenon known as acid rain. For thisreason, in most jurisdictions, it is required by law to minimize sulfuremissions to the environment.

Sulfur is commonly removed from natural gas and other refined petroleumproducts by a catalytic process known as hydrodesulfurization (HDS),also commonly referred to as hydrotreating (HDT) or hydroprocessing(HDP). In this process, the hydrocarbon stream is mixed with hydrogengas, heated, and passed over a fixed catalyst bed at elevatedtemperature and pressure. Commonly used catalysts for hydroprocessingcomprise one or more Group VIIIB metals, such as cobalt (Co) or nickel(Ni) and one or more Group VIB metals, such as molybdenum (Mo) ortungsten (W) supported on a carrier material, such as alumina (Al₂O₃),silica alumina, zeolite, or combinations thereof. When a hydrotreatingcatalyst is used in a hydrotreating process, the activity of thecatalyst decreases over time, due to the accumulation ofcarbon-containing deposits, referred to as coke, on the catalyst and/orby the presence of deactivating inorganic materials, such as silicon(Si), arsenic (As), and vanadium (V). Some of these catalysts may bereactivated by regeneration or rejuvenation and reused as HDS catalysts,but more often the spent catalysts are not recovered and, instead, aretreated as hazardous waste. Thus, environmental and economic incentivesexist for developing further uses for catalysts recovered fromhydrocarbon processes such as HDS treatment.

SUMMARY

Disclosed herein is a method of treating a gas stream in a tailgastreating process, the method comprising: contacting the gas stream witha catalyst that was previously used in a hydrotreating process and thathas been reactivated by a reactivation process prior to contacting thegas stream in the tailgas treating process, wherein the gas streamcomprises one or more sulfur-containing species selected from the groupconsisting of elemental sulfur (S_(x)), sulfur dioxide (SO₂), carbonylsulfide (COS), and carbon disulfide (CS₂), and wherein contacting thegas stream with the reactivated catalyst in the presence of hydrogen(H2) converts the one or more sulfur-containing species to hydrogensulfide (H2S). According to some embodiments, the hydrotreating processis selected from the group consisting of petroleum hydrotreatingprocesses, hydrodesulfurization (HDS), hydrodenitrogenation (HDN),hydrogenation, hydrodemetallization (HDM), naphtha hydrotreating (NHT),diesel hydrotreating (DHT), kerosene hydrotreating (KHT), jet fuelhydrotreating (JHT), atmospheric gas oil hydrotreating, vacuum gas oil(VGO) hydrotreating, and fluid catalytic cracker (FCC) feedhydrotreating. According to some embodiments, the catalyst comprises oneor more Group VIIIB metals and one or more Group VIB metals supported onan inorganic oxide carrier material. According to some embodiments, thecatalyst comprises cobalt and molybdenum supported on aluminum oxide.According to some embodiments, the catalyst comprises nickel andmolybdenum supported on aluminum oxide. According to some embodiments,the reactivation process comprises regeneration. According to someembodiments, the regeneration comprises heating the catalyst in anoxygen-containing atmosphere at a temperature of 300 to 500° C. for atime of 30 minutes or more. According to some embodiments, prior to theregeneration treatment, hydrocarbons are removed from the catalyst bysolvent extraction or by contacting the catalyst with steam, natural gascombustion products, hydrogen or nitrogen at a temperature of 150 to550° C. According to some embodiments, the reactivation processcomprises rejuvenation. According to some embodiments, the rejuvenationcomprises impregnating the catalyst with a solution containing achelating agent and drying the catalyst at a temperature of 50° C. to300° C. According to some embodiments, the chelating agent is an organicacid. According to some embodiments, the reactivated catalyst ispre-sulfurized prior to contacting the gas stream in the tailgastreating process. According to some embodiments, the reactivatedcatalyst is pre-sulfided prior to contacting the gas stream in thetailgas treating process. According to some embodiments, the reactivatedcatalyst is resized, reshaped, and/or reformulated prior to contactingthe gas stream in the tailgas treating process. According to someembodiments, the reactivated catalyst is resized by length grading thecatalyst. According to some embodiments, the resizing, reshaping, and/orreformulating comprises milling the reactivated catalyst to a finepowder and then reforming the reactivated catalyst. According to someembodiments, the reactivated catalyst is resized from having a diameterof 1.3 to 2.5 mm to having a diameter of 3 to 5 mm. According to someembodiments, contacting the gas stream with the reactivated catalystcomprises combining the reactivated catalyst with a second catalyst,wherein the second catalyst provides a lower pressure drop than thereactivated catalyst. According to some embodiments, contacting the gasstream with the reactivated catalyst comprises short loading thereactivated catalyst. According to some embodiments, the reactivatedcatalyst exhibits a pressure drop of 0.05 to 0.20 psi/ft, whensock-loaded and tested at 100 ft/min superficial velocity in ambientair.

Also disclosed herein is a method of forming a reactivated catalyst fora tailgas treating process, the method comprising: obtaining a spentcatalyst from a hydrotreating process, and reactivating the catalyst toform the reactivated catalyst, wherein the reactivated catalyst, whencontacted with a gas stream comprising one or more sulfur-containingspecies selected from the group consisting of elemental sulfur (S_(x)),sulfur dioxide (SO₂), carbonyl sulfide (COS), and carbon disulfide(CS₂), is capable of catalyzing the conversion of the one or moresulfur-containing species to hydrogen sulfide (H₂S) in the presence ofhydrogen (H₂). According to some embodiments, the hydrotreating processis selected from the group consisting of petroleum hydrotreatingprocesses, hydrodesulfurization (HDS), hydrodenitrogenation (HDN),hydrogenation, hydrodemetallization (HDM), naphtha hydrotreating (NHT),diesel hydrotreating (DHT), kerosene hydrotreating (KHT), jet fuelhydrotreating (JHT), atmospheric gas oil hydrotreating, vacuum gas oil(VGO) hydrotreating, and fluid catalytic cracker (FCC) feedhydrotreating. According to some embodiments, the spent catalystcomprises: an inorganic oxide support material having a surface area of20 to 600 m²/g, one or more Group VIIIB metals, and one or more GroupVIB metals supported on the inorganic oxide support material. Accordingto some embodiments, the catalyst comprises cobalt and molybdenumsupported on aluminum oxide. According to some embodiments, the catalystcomprises nickel and molybdenum supported on aluminum oxide. Accordingto some embodiments, the reactivating comprises regeneration. Accordingto some embodiments, the regeneration comprises heating the catalyst inan oxygen-containing atmosphere at a temperature of 300 to 500° C. for atime of 30 minutes or more. According to some embodiments, prior to theregeneration, removing hydrocarbons from the catalyst by solventextraction or by contacting the catalyst with steam, natural gascombustion products, hydrogen or nitrogen at a temperature of 150 to550° C. According to some embodiments, the reactivating comprisesrejuvenation. According to some embodiments, the rejuvenation comprisesimpregnating the catalyst with a solution containing a chelating agentand drying the catalyst at a temperature of 50° C. to 300° C. Accordingto some embodiments, the chelating agent is an organic acid. Accordingto some embodiments, the method further comprises pre-sulfurizing thereactivated catalyst. According to some embodiments, the method furthercomprises pre-sulfiding the reactivated catalyst. According to someembodiments, the method further comprises resizing, reshaping, and/orreformulating the reactivated catalyst. According to some embodiments,the method further comprises milling the reactivated catalyst to a finepowder and then reforming the reactivated catalyst. According to someembodiments, the spent catalyst, prior to reactivating, has a diameterof 1.3 to 2.5 mm and the reformed reactivated catalyst has a diameter of3 to 5 mm. According to some embodiments, the spent catalyst, as used inthe hydrotreating process, exhibits a pressure drop of 0.20 to 0.80psi/ft, and wherein the method further comprises resizing, reshaping,and/or reformulating the reactivated catalyst so that the reactivatedcatalyst exhibits a pressure drop of 0.05 to 0.20 psi/ft, whensock-loaded and tested at 100 ft/min superficial velocity in ambientair.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a process for treating a sour hydrocarbon feed, wherein theprocess includes a hydroprocessing step and a sulfur treatment step.

FIG. 2 is a table showing analysis of regenerated, hot nitrogenstripped, and solvent extracted catalysts.

FIG. 3 is a table showing performance of fresh, regenerated,rejuvenated, hot nitrogen stripped, and solvent extracted catalysts fortailgas treatment at 1,200 GHSV.

FIG. 4 shows an equation used to calculate overall sulfur conversion anda comparison of overall sulfur conversion using the different catalysts.

FIG. 5 is a table showing performance of regenerated and rejuvenatedcatalysts for tailgas treatment at 3,000 GHSV.

FIG. 6 shows a comparison of sulfur dioxide conversion at 3000 GHSVusing different catalysts.

FIG. 7 shows a comparison of carbon disulfide conversion at 3000 GHSVusing different catalysts.

FIG. 8 shows a comparison of carbonyl sulfide conversion at 3000 GHSVusing different catalysts.

FIG. 9 shows a comparison of overall sulfur conversion at 3000 GHSVusing different catalysts.

FIG. 10 shows a process for reactivating a catalyst for use in tailgastreatment.

DETAILED DESCRIPTION

FIG. 1 illustrates aspects of a hydrocarbon processing plant such as anatural gas processing facility or a petroleum refinery. As mentionedabove, such facilities may include one or more hydrodesulfurization(HDS) reactors 102. A sour hydrocarbon feed (i.e., a hydrocarbon feedcontaining organo-sulfur compounds) is provided to the HDS reactor 102.As mentioned above, the hydrocarbon stream is heated, mixed withhydrogen gas, and passed over a catalyst at elevated temperature andpressure. As also mentioned above, catalysts for hydroprocessingtypically comprise one or more Group VIIIB metals, such as cobalt (Co)or nickel (Ni) and one or more Group VIIB metals, such as molybdenum(Mo) or tungsten (W) supported on a carrier material, such as alumina(Al₂O₃), silica alumina, zeolite, or combinations thereof. The reactionthat takes place, hydrogen lysis, is characterized by cleavage of a C—Schemical bond and formation of C—H and H—S chemical bonds. In this way,the reaction of the hydrocarbon compounds (containing the embeddedsulfur) with hydrogen allows liberation of the sulfur by formation ofhydrogen sulfide gas (H₂S).

The effluent of the fixed bed reactor is cooled, and the gas and liquidare separated. The gas contains hydrogen and hydrogen sulfide, amongother components. The gas is fed to an amine system 104. The aminesystem 104 includes an amine absorption system (not specifically,illustrated) where the hydrogen sulfide is selectively absorbed into anamine absorbent. The gas is purified of hydrogen sulfide in this way andthe remaining hydrogen rich gas stream is primarily recycled to becombined with fresh makeup hydrogen and fed once more to thehydrodesulfurization reactor 102. Within the amine system 104 the “rich”H₂S-laden amine solution is sent to an amine regenerator (notspecifically illustrated). The hydrocarbon liquid from the hydrotreatereffluent gas separator is routed to a stripper 106, where the hydrogensulfide is stripped from the hydrocarbon liquid. This purifies theliquid hydrocarbon stream of hydrogen sulfide for further refining. Thestripped hydrogen sulfide containing gas stream is then routed to anamine system 108 (similar to amine system 104), where the amineabsorbent is used to remove the hydrogen sulfide from the rest of thegas stream. Upon regeneration of the rich hydrogen sulfide laden amineabsorbent, a hydrogen sulfide rich gas stream is obtained. Mosttypically, the hydrogen sulfide streams are sent to a sulfur recoverysystem, which may comprise a modified Claus process coupled with a tailgas cleanup process, for further processing and conversion to elementalsulfur. In some cases, though less common, the hydrogen sulfidecontaining streams can be converted instead to sulfuric acid in a wetsulfuric acid (WSA) plant.

Still referring to FIG. 1, the illustrated sulfur recovery system 110includes a modified Claus process 112 that converts hydrogen sulfide toelemental sulfur. This process includes a thermal stage, typically areaction furnace, followed by two or more catalytic stages. In thethermal stage, one-third of the hydrogen sulfide in the feed stream iscombusted to yield sulfur dioxide, according to reaction 1. The sulfurdioxide reacts with hydrogen sulfide to produce elemental sulfuraccording to the Claus reaction, reaction 2. Thus, the overall reactioncan be expressed according to reaction 3.

H₂S+3/2O₂↔SO₂+H₂O  Reaction 1: H₂S Combustion

2H₂SO₂↔3/8S₈+2H₂O  Reaction 2: Claus Reaction

3H₂S+3/2O₂↔3/8S₈+3H₂O  Reaction 3: Overall Reaction

The hydrogen sulfide-containing feed stream(s) are combusted, and theamount of air is controlled to achieve the desired level of sulfurdioxide, as well as to convert any ammonia and hydrocarbons present.Typically, about 60-70% of the sulfur entering the modified Clausprocess is converted to elemental sulfur in the thermal stage. The gasfrom the thermal stage is then processed in each of the consecutivecatalytic stages. Each catalytic stage consists of three process steps:reheat, catalytic conversion, and condensation. In the reheat step, thegas stream is heated to the desired temperature for the subsequentcatalytic conversion stage. In the catalytic conversion step, additionalClaus conversion according to reaction 2 is realized with a Clauscatalyst, which is typically titania or alumina based. The last step iscondensation of the gaseous sulfur formed in the upstream catalyticconverter to liquid sulfur, which is then separated and recovered.Typically, greater than 97% sulfur recovery efficiency cannot beachieved by the modified Claus process alone: For greater sulfurrecovery, for example in the 98-99.9% range, which is required in manyjurisdictions, a tailgas cleanup process is required.

Thus, the illustrated sulfur recovery system 110 also includes a tailgascleanup process 114. A common sulfur recovery tailgas cleanup system 114includes a hydrogenation/amine treatment, which may provide 99.8+%sulfur recovery efficiency. Stringent environmental regulations,imposing mandatory low emissions and high recovery limits, have forcedmany sour gas processors to adopt such hydrogenation/amine-type tailgastreatment processes.

One of the most common hydrogenation/amine treatment processes is theShell Claus Offgas Treating (SCOT) process. In the SCOT process, thesulfur dioxide and other convertible sulfur compounds in Claus tailgasare catalytically converted to hydrogen sulfide. First the Claus tailgasis heated and mixed with a reducing gas stream containing hydrogen andcarbon monoxide. The reducing gas is commonly generated by a reducinggas generator (RGG) 116 operating at sub-stoichiometric combustionconditions to partially oxidize the fuel into carbon monoxide andhydrogen. The resulting gas stream obtained by mixing of the Claustailgas and reducing gas, which contains species including sulfurdioxide (SO₂), carbonyl sulfide (COS), and carbon disulfide (CS₂),elemental sulfur (S_(x)), and carbon monoxide (CO), is then passed overa hydrogenation catalyst in a hydrogenation reactor 118. Thehydrogenation catalyst most typically contains cobalt and molybdenum onan alumina support. The catalyst facilitates the hydrogenation ofresidual sulfur dioxide (reaction 4), hydrolysis of carbonyl sulfide(reaction 5), hydrolysis of carbon disulfide (reaction 6), andhydrogenation of elemental sulfur (reaction 7), all back to H₂S.

SO₂+3H₂→H₂S+2H₂O  Reaction 4: SO₂ Reduction

COS+H₂O→H₂S+CO₂  Reaction 5: COS Hydrolysis

CS₂+2H₂O→2H₂S+CO₂  Reaction 6: CS₂ Hydrolysis

1/8S₈+H₂→H₂S  Reaction 7: Sulfur Reduction

The catalyst also facilitates a water-gas shift reaction, where carbonmonoxide and water react to form hydrogen and carbon dioxide, perreaction 8.

CO+H₂O→H₂+CO₂  Reaction 8: Water-Gas Shift

The reactor effluent is typically cooled by a waste heat boiler(generating low pressure steam) followed by a water quench tower system,which both cools the gases and lowers the water content from about 30%to 5-10%. The cooled gas from the cool/quench equipment 120 is thencontacted with an amine absorbent in an amine contactor column. In theamine absorption system 122, the H₂S in the tailgas is absorbed into thelean amine, making it rich (laden with H₂S) and purifying the gas streamof H₂S. The purified off-gas stream is then routed to an incinerator asthe final treatment step before release to the atmosphere. The richamine is routed to an amine regenerator where it is heated to drive offthe H₂S, which is recycled back to the Claus plant for conversion toelemental sulfur. In this way, the sulfur is basically recycled toextinction. The lean, regenerated amine is fed back to the absorber foranother H₂S pickup cycle.

It should be noted that FIG. 1 is intended to provide an overview of theSCOT process and is not intended to illustrate every piece of equipmentand every variable. It should also be noted that other variants of atailgas clean system are known in the art. For example, one variant ofthe original SCOT process is the Low Temperature SCOT process. In theconventional SCOT process, the tailgas stream is typically directlyheated using an in-line burner (i.e., RGG 116) to about 260-300° C.before being fed to the hydrogenation reactor 118. In the lowtemperature SCOT process, the tailgas stream is typically indirectlyheated using a high-pressure steam heater, typically to about 220-230°C. The low temperature SCOT process also requires the use of an externalhydrogen source, since the reducing gas generator is no longer a part ofthe process scheme. Lastly, low temperature units typically use acatalyst that is specifically designed for higher activity, usually byusing higher concentrations of active metals, to achieve a similar levelof conversion as conventional temperature units.

Another alternative tailgas clean-up process is the Beavon SulfurRemoval (BSR) process, which also features hydrogenation of the Claustailgas. In the BSR process, Claus tailgas is heated by an in-lineburner (e.g., a reducing gas generator, RGG) at sub-stoichiometricconditions to partially oxidize the fuel to generate reducing gases. Themixture of Claus tailgas and reducing gases are fed to a hydrogenationbed packed with cobalt and molybdenum on alumina catalyst. The samereactions as listed above for the SCOT process (4-8) occur in thehydrogenation step. After the hydrogenation step, the gas is sent to awaste heat boiler, which generates low pressure steam, followed by aquench tower system, which both lowers the temperature and significantlyreduces the water content. It is common to pair the BSR process withanother process which aims to either recycle the H2S gas (for exampleBSR/MDEA) or convert the tin gas into elemental sulfur for recovery (forexample BSR/Selectox or BSR/Stretford).

Notice that each of the tailgas clean-up processes described hereinvolve a hydrogenation reactor that effects the reactions 4-7 describedabove. Notice also that the hydrogenation catalysts implemented in thehydrogenation reactors of the tailgas clean-up process typicallycomprise one or more Group VIIIB metals, such as cobalt (Co) or nickel(Ni) and one or more Group VIB metals, such as molybdenum (Mo) ortungsten (W) supported on a carrier material, such as alumina (Al₂O₃),silica alumina, zeolite, or combinations thereof.

Aspects of the present disclosure involve obtaining catalyst that wasused in a hydrotreating process, and then using the so-obtained catalystin a tailgas treating process. The applications from which thehydrotreating catalyst originates can include, but are not limited to,catalyst used in hydrodesulfurization (HDS), hydrodenitrogenation (HDN),hydrodemetallization (HDM), hydrodearomatization (HDA),hydrodeoxygenation (HDO), aromatic saturation, hydrocracking and otherhydrogenation processes. For example, the spent catalyst may originatefrom the application of naphtha hydrotreating (NHT), dieselhydrotreating (MIT), kerosene hydrotreating (KHT), jet fuelhydrotreating (THT), atmospheric gas oil hydrotreating, vacuum gas oil(VGO) hydrotreating, fluid catalytic cracker (FCC) feed hydrotreating,or any other petroleum fraction hydrotreating application. It isimportant to note that when referring to a hydrotreating catalyst, thisterm is not intended to include a catalyst that was previously used in aClaus tailgas treating process. The catalysts typically comprise one ormore Group VIIB metals, such as cobalt (Co) or nickel (Ni) and one ormore Group VIB metals, such as molybdenum (Mo) or tungsten (W) supportedon a carrier material, such as alumina (Al₂O₃), silica alumina, zeolite,or combinations thereof. These hydroprocessing catalysts can also haveType I or Type II active sites. The catalyst may also include promoters,such as boron or phosphorous promoters, among others.

As used herein, the term “reactivated catalyst,” refers to a catalystobtained from the hydrotreating process, submitted to a reactivationtreatment, and then re-used in a tailgas treating process. A reactivatedcatalyst may be regenerated and/or rejuvenated (revitalized) catalyst.

The term “regenerated catalyst” is used herein to refer to a spentcatalyst that has been submitted to in-situ or ex-situ controlledthermal treatment in the presence of oxygen to remove contaminants suchas volatile hydrocarbons, carbon (coke), and sulfur. Regenerationprocesses are known to those skilled in the art, and although theseprocesses may differ in configuration details, they are all aimed atremoving hydrocarbons, sulfur, and carbon, converting substantially allthe metals to their oxide form, and recovering as much activity aspossible, all while minimizing breakage to realize the highest yield andlowest product length loss possible. Most catalyst regeneration isperformed ex-situ, however in-situ regeneration can be performed, andthe term regenerated as used herein is not intended to limit the scopeto ex-situ regeneration only. Regeneration processes are commonly usedon spent hydrotreating catalysts to recover a portion of the freshcatalyst activity from the spent catalyst. Regenerated catalysts aretypically re-used in a lower severity hydrotreating unit as a lower costalternative to fresh catalyst. Regeneration processes differ fromrejuvenation (revitalization) processes in that they do not feature anyprocess of metals re-dispersion to reverse the activity decline frommetals agglomeration.

According to some embodiments, a regenerated catalyst can be prepared byobtaining a catalyst used in a hydrotreating process, as describedabove. The obtained catalyst can be regenerated by heating the catalystin air to remove contaminants from the hydroprocessing process from thecatalyst. For example, the catalyst may be heated within a temperaturerange of about 200° C. to about 600° C., more preferably 380° C. toabout 500° C. for 1-24 hours, more preferably 1-3 hours. One of the keycontaminants removed during the regeneration process is coke, Typicallyspent catalyst has a coke concentration of greater than 4 wt. %. Afterregeneration, the coke concentration is typically less than 4 wt. %.

The term “rejuvenated” (or revitalized) catalyst is used herein to referto a spent catalyst that has been submitted to an in-situ or ex-situcontrolled thermal treatment (regeneration) to remove volatilehydrocarbons, carbon (coke), and sulfur, followed by an ex-situapplication of a chelating agent via impregnation to re-disperse activemetal sites on the support that have migrated, causing metal sitegrowth. After a specified aging period, the catalyst can be dried to thefinal product form. Rejuvenation processes are known to those skilled inthe art, and although these processes may differ in configurationdetails, they are all aimed at removing hydrocarbons, sulfur, andcarbon, converting substantially all of the metals to their oxide form,re-dispersing the active metal sites on the support, recovering as muchactivity as possible, all while minimizing breakage to realize thehighest yield and lowest product length loss possible. Rejuvenationprocesses often recover enough activity to be close to fresh catalyst interms of performance. In some cases, especially with regards to Type Icatalysts, rejuvenation of spent catalyst can provide even higherperformance than the original fresh catalyst (under hydrotreatingconditions). Because of the higher degree of activity recovery comparedto regenerated catalyst, a rejuvenated catalyst may be re-used in thesame unit it was harvested from or one of similar severity. It does notnecessarily have to be cascaded to a lower severity unit likeregenerated catalyst often is.

Any rejuvenation process known in the art may be used according to theinstant disclosure. According to some embodiments, a rejuvenatedcatalyst can be prepared by obtaining a catalyst used in a hydrotreatingprocess, as described above. According to some embodiments, the obtainedcatalyst is first regenerated as described above. Following theregeneration process, the catalyst can be contacted with one or morereagents to rejuvenate the catalyst. Examples of reagents that may beused to contact the catalyst include one or more organic additives suchas butanediol, pyruvic aldehyde, glycolic aldehyde, ethylene glycol,propylene glycol, glycerin, trimethylol ethane, trimethylol propane,diethylene glycol, dipropylene glycol, trimethylene glycol triethyleneglycol, tributylene glycol, tetraethylene glycol, tetrapentylene glycol,polyethers like polyethylene glycol, ethylene glycol monobutyl ether,diethylene glycol monomethyl ether, diethylene glycol monoethyl ether,diethylene glycol monopropyl ether, and diethylene glycol monobutylether. The catalyst may be contacted with a solution comprising theorganic additive, such as a solution of the organic additive in analcohol or an aqueous solution, for example. Alternatively, oradditionally, the catalyst may be contacted with an acid such asglycolic acid, glyoxylic acid, lactic acid, diethylene triamine pentaacetic acid, ethylene amine tetra acetic acid, citric acid, tartaricacid, oxalic acid, malonic acid, malic acid, or the like. Followingcontacting, the catalyst may be aged and/or dried. For example, thecatalyst may be aged for a time ranging from hours to several days, forexample, 1 hour to 24 hours, 6 to 24 hours, or for example, about 14hours. According to some embodiments, the catalyst may be aged at roomtemperature. As used herein, “room temperature” refers to a temperatureof about 20-25° C. According to some embodiments, a portion of theorganic additive may remain in the catalyst even after drying.

Common commercial rejuvenation processes are exemplified by thefollowing: EXCEL® (by Porocel, Houston, Tex.) described in U.S. Pat. No.9,895,679, ENCORE® (by Criterion, Houston, Tex.) described in U.S. Pat.No. 7,696,120, REACT® (by Albemarle Corporation, Charlotte, N.C.)described in U.S. Pat. No. 7,956,000, and REFRESH® (by Haldor Topsoe,Inc., Houston, Tex.). The contents of U.S. Pat. No. 9,895,679 (“the '679Patent”) are incorporated herein by reference in their entirety.

According to some embodiments, the reactivated (i.e., regenerated orrejuvenated) catalyst can be either applied “as-is,” i.e., in theoriginal size, shape, and composition as was used in the hydrotreatingprocess. According to other embodiments, the catalyst may be re-sized,re-shaped, reformulated, or any combination of resizing, reshaping, andreformulating, prior to use in a tailgas treating process. Resizinginvolves changing the size of the catalyst. This can be accomplished,for example, by length grading the catalyst, which involves selectivelyremoving the smallest catalyst particles, effectively increasing theaverage particle size of the remaining catalyst. Length grading can beaccomplished by sieving/screening or by other, more specialized methodsknown to those skilled in the art. Resizing can also be accomplished bymeans of milling the catalyst to a fine powder and re-forming adifferent sized catalyst. For example, resizing may involve milling a1.3 mm, 1.6 mm, or 2.5 mm catalyst extrudate to a fine powder andreforming to produce a 3.0 mm or 3.5 mm catalyst extrudate. Re-shapinginvolves changing the shape of the catalyst. For example, re-shaping mayinvolve milling a tri-lobe or quad-lobe catalyst extrudate to a finepowder and reforming to produce a cylindrical extrudate, sphericalproduct, or even a ring/hollow cylinder product. Resizing and reshapingmay first involve reducing the catalyst from the “as-is” form to apowder by a milling operation. The forming of the new size or shape canthen be accomplished by any forming method, including but not limitedto: extrusion (e.g., screw or piston extrusion), tableting, ballforming, nodulation, granulation, drop coagulation, etc.

Reformulating involves the incorporation of additional components ormaterials to the reactivated catalyst. For example,boehmite/pseudo-boehmite alumina or anatase titania powder may be addedin a certain proportion with milled catalyst powder to produce areformulated product. Reformulation may involve the addition of activemetals, promoters, or other ingredients by physical mixing such asco-mulling, admixing, plow mixing, paddle mixing or ribbon mixing, forexample. It may also involve the addition of metals, promoters, or otheringredients by precipitation or impregnation, for example.Alternatively, reformulating may involve a combination of physicalmixing and impregnation to introduce additional components to thereactivated catalyst material. Any method in which additional componentsare added to the reactivated catalyst in any form constitutesreformulation. For example, the catalyst may be reformulated by takingthe catalyst in its native form and wetting the catalyst with a solutionor a slurry of active phase precursors, for example, soluble metal saltsof one or more Group VIIIB metals, such as cobalt (Co) or nickel (Ni)and one or more Group VIB metals, such as molybdenum (Mo) or tungsten(W). For example, the catalyst may be re-formulated by wet impregnationwith an excess of solution, dry impregnation (otherwise known asincipient wetness impregnation or pore volume impregnation), orprecipitation.

Generally, a tailgas catalyst can be installed in one of three states:the oxidic state, the pre-sulfurized state, or the pre-sulfided(pre-activated) state. The oxidic state may be described as a state inwhich nearly all the metals are present in the metal oxide form andthere is no significant amount of sulfur present on the catalyst as wellas no significant amount of metal sulfides. Pre-sulfurizing may bedescribed as a treatment in which elemental sulfur and/or sulfurcontaining compounds are added to the catalyst, typically with less than60% of the metal oxides converted into metal sulfides. Pre-sulfiding(pre-activation) may be described as a treatment in which typicallygreater than 60% of the metal oxides are converted to metal sulfides.The advantages of pre-sulfurizing or pre-sulfiding (pre-activating)treatments (versus the oxidic state) are primarily faster and easierreactor startup after initial loading. The reactivated hydroprocessingcatalysts, whether in the native or resized, reshaped, and/orreformulated state, may be submitted to a pre-sulfurizing orpre-sulfiding treatment prior to use in the target application. Thedisclosure and the claims set forth herein is not intended to limit thescope to any specific pre-sulfurizing or pre-sulfiding technology but isinstead intended to apply to them all.

The inventors have found that, surprisingly, catalyst from ahydrotreating application may be reactivated to be fit for use in atail-gas hydrogenation application. A beneficial aspect of the disclosedmethods and systems is that the re-use of spent hydroprocessing catalystreduces hazardous waste generation by operators from spent catalystdisposal. Ultimately, this helps reduce the environmental impact (carbonfootprint) of the catalyst life cycle. The disclosed methods and systemsalso provide an economically attractive source of high-performancecatalyst for tailgas treatment, which benefits the spent catalystgenerator, the catalyst provider, and the catalyst consumer, all throughbeneficial reuse of an otherwise hazardous waste.

Persons of skill in the art will appreciate that some aspects ofcatalysts used for tailgas treatment (i.e., hydrogenation of tailgascomponents) may differ from aspects of catalysts used in non-tailgastreating operations (such as the hydroprocessing and other processesdescribed above). In other words, even though the catalysts for bothtypes of processes may use similar group metals supported on similarcarrier materials, the catalysts may be optimized for one or the othertypes of processes. For example, a common difference between catalystsused in hydroprocessing applications and those used in tailgas treatingis size. Typically, hydroprocessing catalysts are available in smallersizes, for example, diameter sizes of 1.3 mm, 1.6 mm, or 2.5 mmextrudates are very common, while tailgas catalysts are available inlarger sizes, typically with diameters from 3 to 5 mm in variousshapes/forms. Another distinction between the typical hydroprocessingcatalyst and the typical tailgas catalyst comes in the metals used andmetals concentrations. Commercial tailgas catalysts on the market todayare predominantly cobalt and molybdenum (CoMo) active metals, withtypical concentration ranges of 2-3.5% Co and 6-11% Mo. Commercialhydrotreating catalysts on the market today are primarily cobalt andmolybdenum (CoMo) or nickel and molybdenum (NiMo) active metalscombinations. For commercial CoMo hydrotreating catalysts, typicalconcentration ranges are 3-4.5% Co and 12-17% Mo. For commercial NiMohydrotreating catalysts, typical concentration ranges are 2.5-5% Ni and9-19% Mo. Notice that the active metals content is typically much higherfor hydrotreating catalysts than for tailgas catalysts. Notice also thatit is not a common commercial practice, as it is in hydroprocessingservice, to use Ni and/or W containing catalysts in tailgas service.Another distinction between the two catalysts is their shape.Hydroprocessing catalysts are predominantly multi-lobed extrudateswhereas tail gas catalysts come in a variety of shapes, includingmultilobed extrudates, spherical forms, and even hollow cylinderextrudates. Another distinction between the two types of catalysts isthat hydrotreating catalysts almost exclusively comprise extrudedgamma/delta/theta alumina phase catalyst supports whereas tailgascatalysts comprise both spherical chi/rho/eta alumina phase catalystsupports, and extruded gamma/delta/theta alumina phase catalystsupports.

One limitation of using reactivated hydrotreating catalysts in a tailgasservice is the size difference of the catalyst particles. This isperhaps one reason why, to the knowledge of the inventors, it has neverbeen done. As already mentioned, hydroprocessing catalysts are typicallyof a smaller size than tailgas catalysts (1.3-2.5 mm vs. 3-5 mm,respectively). Catalysts of a smaller size cause higher packed-bedpressure drop per linear foot. There are many cases where thishigher-pressure drop may be unacceptable due to the hydraulic capacitylimitations it would impose on the tailgas unit. Fortunately, theinventors have identified several ways to circumvent this obstacle. Oneoption is to length grade the catalyst. Length grading is a commerciallyestablished process which separates catalyst particles based on theirsize. By doing so, the smallest particles can be effectively removedwhich increases the average length of the remaining catalyst extrudateparticles. By increasing the average particle length of the catalystextrudates and tightening up the particle size distribution, the bedvoid fraction also increases. Both of these changes cause a lowerpressure drop per linear foot. Within certain limits, the extent oflength grading can be tailored to the desired pressure drop profile.Length grading can be accomplished by either screening/sieving, or othermore specialized method. Another option is to load a shorter bed of highactivity reactivated hydroprocessing catalyst than would normally beloaded for fresh tailgas catalyst in order to target both the desiredpressure drop and performance profile of a standard fresh tailgascatalyst loading configuration. This is called “short-loading” and ispossible because in some cases, the reactivated hydroprocessingcatalysts have been shown to perform better than competitive freshtailgas catalysts being sold in the market today. Another option is tocombine a high activity and high pressure drop reactivatedhydroprocessing catalyst with a lower pressure drop (larger particlesize) fresh or reactivated tailgas catalyst in a layered bedconfiguration in order to target the desired performance and pressuredrop profiles. Another option is to combine a high activity and highpressure drop reactivated hydroprocessing catalyst with a low pressuredrop (larger particle size) resized, reshaped, and/or reformulatedcatalyst to target the desired performance and pressure drop.

Each of these options allow pressure drop limitations to be mitigatedand a reactivated hydrotreating catalyst to be made suitable forapplication in a tailgas unit. According to some embodiments, thecatalyst, as used in the original hydrotreating process would cause apressure drop of about 0.20 psi/ft to about 0.80 psi/ft, for exampleabout 0.40 psi/ft to about 0.60 psi/ft, when sock-loaded and tested at asuperficial velocity of 100 ft/min in ambient air. After the catalyst isresized, reshaped, reformulated, short loaded, and/or combined withanother lower pressure drop catalyst for tailgas treatment using one ofthe methods described above, the catalyst may cause a pressure drop ofabout 0.05 psi/ft to about 0.20 psi/ft, for example about 0.10 psi/ft toabout 0.15 psi/ft, when sock-loaded and tested at a superficial velocityof 100 ft/min in ambient air.

One or more of the resizing, reshaping, and reformulating stepsdescribed above may be used to reconfigure a catalyst obtained from afirst, non-tailgas treatment process to optimize the catalyst fortailgas treating. FIG. 10 illustrates an embodiment of a process 1500for reactivating a catalyst for tailgas treating. First a catalyst isobtained from a non-tailgas treatment process 1502. The catalyst may bea tri-lobe or quad-lobe catalyst, for example, and may typically have asize of about 1.3-2.5 mm. As mentioned above, the catalyst may compriseone or more Group \AIM metals and one or more Group VIB metals supportedon a carrier material, such as alumina (Al₂O₃), silica alumina, zeolite,or combinations thereof.

The obtained catalyst may be thermally stripped or solvent extracted1504, typically to remove residual hydrocarbons from the catalyst. Forexample, the thermal stripping process may involve contacting thecatalyst with hot steam or gas, air, natural gas combustion products,hydrogen or nitrogen at a temperature from 150° C. to 550° C. Forexample, the solvent extraction process may involve contacting thecatalyst with a non-polar solvent. The stripped or solvent extractedcatalyst may be regenerated 1506, as described above. For example, thecatalyst may be heated at a temperature of about 200° C. to about 600°C., more preferably 380° C. to about 500° C. for 1-2.4 hours, morepreferably 1-3 hours. The regenerated catalyst may be resized 1508,typically by grinding or milling the regenerated catalyst to form apowder. The powder may be isolated, for example, by screening. Thepowder may be reformulated 1510 in one or more aspects. For example, thepowder may be combined with additional carrier material, such asalumina, thereby, adjusting the relative loading of the active catalystmaterials (i.e., metals). The catalyst may be reshaped 1512, forexample, by extruding the resized and reformulated material into a shapethat is the same or different than the original catalyst shape. Forexample, the original catalyst may have been multi-lobed with a givennumber of lobes (e.g., tri-lobed or quad-lobed) and it may be reshapedto yield a cylindrical or spherical shaped catalyst. It should be notedthat the catalyst may be further reformulated after reshaping. Forexample, the reshaped catalyst may be impregnated with further activematerials (e.g., cobalt, nickel, and/or molybdenum precursor materials).The catalyst may be rejuvenated 1514. For example, the newly shapedcatalyst may be exposed to one or more rejuvenation reagents andprocesses as described above. According to some embodiments, thecatalyst is impregnated using a chelating material as described above,aged, and dried. According to some embodiments, the chelating materialcan include an organic additive, a portion of which remains in thecatalyst material following the rejuvenation process.

It should be noted that the process 1500 is only exemplary. Some of thesteps may be omitted or the steps may be conducted in a different order.For example, the catalyst obtained from the original (non-tailgastreatment) process may be regenerated and rejuvenated prior to resizingand reshaping or even be prepared without any resizing or reshaping.Other modifications to the process 1500 will be apparent to a person ofskill in the art based on this disclosure.

The following examples are included to demonstrate aspects of thedisclosed techniques and compositions.

Example 1: Realistic Space Velocity (1,200 GHSV) Testing

A cylindrical vertically oriented glass reactor with an internaldiameter of 3.0 cm and a height of 51 cm was filled with 70 mL ofcatalyst for each catalyst tested. Each of the fresh, regenerated, andExcel® rejuvenated catalyst samples (#1-10 and 13 in list below) weresubmitted to the same testing protocol, which consisted first of anin-situ sulfiding activation step, followed by specified performancetest conditions. During the in-situ sulfiding step, a gas of thefollowing molar composition was passed over the catalyst in down-flowfashion: 2% H₂S, 10% Hz, and 88% Na. The feed gas composition was setusing properly calibrated mass flow controllers for each component andverified by gas chromatography initially. The space velocity of the gasduring the in-situ sulfiding step was 2,000 GHSV. The temperature wasevenly ramped from 200° C. to 315° C. over a period of 16 hours. Theeffluent gas composition was measured every 2 hours by gaschromatography. After the 16 hours was completed, the catalyst wasconsidered to have been fully activated by the in-situ sulfidingcondition. There were two samples tested for which the in-situ sulfidingwas not necessary because the active metals were already in the sulfidestate, the solvent extracted, and hot nitrogen stripped samples (#11 and12, respectively). An alternative activation startup used forpre-activated (pre-sulfided) tailgas catalysts was selected for thesetests. For the alternative activation startup, a gas of the followingmolar composition was passed over the catalyst in down-flow fashion: 3%H₂, 3% CO, 9% CO₂, 25% H₂O, and 60% N₂. The feed gas composition was setusing properly calibrated mass flow controllers for each component andverified by gas chromatography initially. The space velocity of the gasduring the activation step was 500 GHSV. The temperature was evenlyramped from 200° C. to 315° C. over a period of 24 hours. The effluentgas composition was measured every 2 hours by gas chromatography. Afterthe 24 hours was completed, the catalyst was considered to have beenfully activated and ready for performance testing.

After completion of the startup in-situ sulfiding or activation, thecatalyst bed was ready for the performance test conditions. During theperformance test conditions, a gas of the following molar compositionwas passed over the catalyst in down-flow fashion: 70.05% N₂, 25% H₂O,2.33% H₂, 1.20% CO₂, 0.59% CO, 0.47% H₂S, 0.23% SO₂, 0.060% COS, and0.061% CS₂. The feed gas composition was set using properly calibratedmass flow controllers for each component and verified by gaschromatography initially. The space velocity of the gas for theperformance test conditions was 1,200 GHSV, equivalent to a residencetime of 3 seconds, and was intended to represent realistic commercialoperating space velocity. The performance tests occurred at fourdistinct temperature conditions: 220° C., 240° C., 280° C., and 300° C.At each condition, the temperature was held for a time of 12 hours, morethan enough time for performance to reach steady state. Compositionalanalysis of the reactor effluent was performed every 2 hours by gaschromatography. From the feed and average gas analysis at eachperformance test condition, the conversion of SO₂, CS₂, and COS weredetermined.

Thirteen different catalyst samples were tested according to theabove-specified testing protocol. These are listed below:

-   1. Regenerated Commercial Hydroprocessing Catalyst A (2.5 mm    trilobe)-   2. Excel® Rejuvenated Commercial Hydroprocessing Catalyst A (2.5 mm    trilobe)-   3. Regenerated Commercial Hydroprocessing Catalyst B (2.5 mm    quadlobe)-   4. Excel® Rejuvenated Commercial Hydroprocessing Catalyst B (2.5 mm    quadlobe)-   5. Fresh Commercial Hydroprocessing Catalyst C (2.5 mm quadlobe)-   6. Regenerated Commercial Hydroprocessing Catalyst C (2.5 mm    quadlobe) from Application 1.-   7. Regenerated Commercial Hydroprocessing Catalyst C (2.5 mm    quadlobe) from Application 2.-   8. Regenerated Commercial Hydroprocessing Catalyst D (2.5 mm    trilobe)-   9. Excel® Rejuvenated Commercial Hydroprocessing Catalyst D (2.5 mm    trilobe)-   10. Regenerated Commercial Hydroprocessing Catalyst E (2.5 mm    trilobe)-   11. Solvent Extracted Commercial Hydroprocessing Catalyst F (2.5 mm    trilobe)-   12. Hot Nitrogen Stripped Commercial Hydroprocessing Catalyst F (2.5    mm trilobe), and-   13. Fresh Commercial Tailgas Catalyst (3.2 mm trilobe).

Catalyst A was used in diesel (ULSD) hydrotreating service prior to itsreactivation. Following its use in diesel hydrotreating, Catalyst A wastreated by regeneration and Excel® rejuvenation processes, as describedin the above-incorporated '679 Patent. The regeneration processfeatures, in some cases, a fluidized hot air strip to removehydrocarbons and reduce coke content, followed by, in all cases, a highresidence time, moving belt heat soak to remove carbon and sulfurembedded deep in the catalyst pores. The Excel® rejuvenation processinvolves first catalyst regeneration, as just described, followed byimpregnation with a solution of chelating agent into the pores. Theimpregnated catalyst is allowed to age for a specific amount of time andthen dried. The rejuvenation process helps to reverse metalsagglomeration that occurs while the catalyst is in service and as aresult of the regeneration process. While Porocel's regeneration andExcel® rejuvenation processes were used in these examples, regenerationand rejuvenation processes are well-known to those skilled in the artand are described, for example, in the above-referenced patents.

Catalyst B was used to process vacuum gas oil for fluid catalyticcracking feed pretreatment prior to its reactivation. Following its usein vacuum gas oil treating, Catalyst B was treated by regeneration andExcel® rejuvenation processes, as described above.

The fresh sample of commercial hydroprocessing Catalyst C was acquiredin the surplus catalyst market for the purpose of performance testing.

Catalyst C from Application 1 was used in gas oil hydrotreating serviceprior to regeneration. Following its use in gas oil hydrotreating,Catalyst C was treated by a regeneration process, as described above.

Catalyst C from Application 2 was used in kerosene hydrotreating serviceprior to regeneration. Following its use in kerosene hydrotreating,Catalyst C was treated by a regeneration process, as described above.

Catalyst D was used in diesel (ULSD) hydrotreating service prior toreactivation.

Following its use in diesel (ULSD) hydrotreating, Catalyst D was treatedby regeneration and Excel® rejuvenation processes, as described above.

Catalyst E was used in a hydrotreating service prior to reactivation.Following its use in the hydrotreating service, Catalyst E was treatedby a regeneration process.

Catalyst F was used in vacuum gas oil (VGO) pretreatment service forhydrocracking prior to recovery of the spent sample. Following its usein vacuum gas oil (VGO) pretreatment service for hydrocracking, CatalystF was divided into two samples and submitted to two differenttreatments. The first treatment was a Soxhlet solvent extractionperformed with toluene for 4 hours before drying for 2 hours at 110° C.The purpose of the solvent extraction was to remove residualhydrocarbons from the spent catalyst. The second treatment was a hotstrip at 370° C. in a pure nitrogen sweep for 1 hour in a rotary tubecalciner. The hot nitrogen strip was also intended to remove residualhydrocarbons from the spent catalyst sample.

The fresh commercial tailgas catalyst was acquired in the surpluscatalyst market for the purpose of performance testing.

All the hydroprocessing catalysts tested were of the same size and shapeas used for their original service and no reformulation was performed.Catalyst A, B, and C were all different catalysts made by differentmanufacturers and used in different hydrotreating services. Catalyst Aand Catalyst D were made by the same manufacturer, were in the sameservice, and were even originally used in the same reactor but weredifferent catalysts, with Catalyst A being CoMo on alumina and CatalystD being NiMo on alumina. Catalyst C from application 1 and Catalyst Cfrom application 2 were made by the same manufacturer and were the sametype of catalyst but were sourced from different reactors after beingused in different hydrotreating services and both had differentcontaminant profiles. Catalysts A and D-F were all made by the samemanufacturer but were different catalysts, with different types ofmetals and metal concentrations present. Catalysts A-C were all cobaltand molybdenum (CoMo) on alumina support, whereas Catalyst D-F werenickel and molybdenum (NiMo) on alumina support. The fresh tailgascatalyst used for competitive evaluation and the fresh Catalyst Creference sample had seen no prior service and were used in thecompletely fresh form without alteration, just as it would be directlyfrom the manufacturer. Select analytical data for the catalyst samplesthat were performance tested is shown in Table 1 (FIG. 2). The Excel®rejuvenated samples for each catalyst were from the same source materialas the regenerated samples and are expected to be virtually identicalwith respect to the physical properties in Table 1. In the case ofCatalyst F, the metals data was acquired by performing XRF analysis on alab-scale regenerated sample, while the other analytical data were fromthe solvent extracted and hot nitrogen stripped samples in the statethey were in before performance testing. Catalyst A and C were bothphosphorous promoted CoMo on alumina catalysts, whereas Catalyst B was anon-phosphorous promoted CoMo on alumina catalyst. On the other hand,Catalyst D and F were both phosphorous promoted NiMo on aluminacatalysts, whereas Catalyst E was a non-phosphorous promoted NiMo onalumina catalyst. Catalyst E was silicon promoted, whereas all othercatalysts were not. Overall, the list of catalysts tested in Example 1and FIG. 2 show that a good cross section of the hydroprocessingcatalyst market was tested, from CoMo to NiMo, from phosphorous promotedto non-phosphorous promoted, from higher to lower active metalsloadings, from silicon to non-silicon promoted, from fresh toregenerated and rejuvenated (as well as hot nitrogen stripped andsolvent extracted), and from different catalyst types/products,manufacturers, and hydroprocessing applications.

The test results for the above described testing protocol and catalystsare listed in Table 2 (FIG. 3). Looking first at SO₂ conversionperformance, FIG. 3 shows that out of the 36 performance data pointsgenerated at each temperature condition for the nine regenerated andrejuvenated hydroprocessing catalysts in their native form, only fourperformance data points fell below the fresh tailgas competitivereference catalyst. The fact that 32 out of the 36 performance datapoints indicated superior performance (an outperformance rate of almost90%) provides strong evidence that the reactivated hydroprocessingcatalysts can be fit for use in Claus tailgas hydrogenation service.Overall, conversion was very high (>98%) for all the regenerated andrejuvenated hydroprocessing catalysts in their native form that weretested. High SO₂ conversion was also achieved for the solvent extractedand hot nitrogen stripped versions of Catalyst F, with only three out ofeight performance data points falling below the fresh tailgascompetitive reference catalyst. From a practical standpoint, sincehydrogenation of SO₂ proceeds much more readily than the hydrolysis ofCOS and CΩ and, in many cases, closely approaches 100%, it is often moreuseful to compare the performance for hydrolysis of COS and CS₂ betweenthe different catalysts for better resolution and differentiation ofperformance.

Looking next at CS₂ conversion performance, FIG. 3 shows that out of the36 performance data points generated at each condition for the nineregenerated and rejuvenated hydroprocessing catalysts in their nativeform, only one performance data point fell below the fresh tailgascompetitive reference catalyst. The fact that 35 out of the 36performance data points indicated superior performance (anoutperformance rate of 97%) provides compelling evidence that thereactivated hydroprocessing catalysts can be fit for the use of CS₂hydrolysis in Claus tailgas hydrogenation service. One observation worthnoting is that the outperformance of all the hydroprocessing catalyststested when compared to the fresh tailgas competitive reference catalystwas much more pronounced at the 240° C., 280° C., and 300° C.temperature conditions. It is only at the 220° C. condition that thereis a significant (>10%) drop in performance for three out of the nineregenerated and rejuvenated hydroprocessing catalysts in their nativeform. Still, even with this significant drop in performance at 220° C.,all but one of the hydroprocessing catalysts still displayed higher CS₂conversion activity. The hot nitrogen stripped and solvent extractedversions of Catalyst F generally underperformed the fresh tailgascompetitive reference catalyst, with seven out of the eight performancedata points falling below the fresh tailgas competitive referencecatalyst. It is worth noting that the solvent extracted version ofCatalyst F displayed nearly equal but slightly lower performance thanthe fresh tailgas competitive reference, whereas the hot nitrogenstripped version of Catalyst F displayed a widening margin ofunderperformance as temperature decreased.

Looking next at COS conversion performance, FIG. 3 shows that out of the36 performance data points generated at each condition for the nineregenerated and rejuvenated hydroprocessing catalysts in their nativeform, ten performance data points fell below the fresh tailgascompetitive reference catalyst. With 26 out of the 36 performance datapoints indicating superior performance (an outperformance rate of 72%),evidence is provided that these reactivated hydroprocessing catalystscan be fit for the use of COS hydrolysis in Claus tailgas hydrogenationservice. It is worth noting that eight out of the ten data points thatfell below the fresh tailgas competitive reference catalyst were for twoof the three Excel® rejuvenated catalysts tested. In general, it wasobserved that Excel® rejuvenated catalysts showed lower COS conversionperformance than their regenerated counterparts, a surprising finding.Even so, the Excel® rejuvenated catalysts still displayed quite highlevels of COS conversion and did not significantly underperform thefresh competitive tailgas reference. Considering only the regeneratedhydroprocessing catalysts in their native form, the outperformance rateincreases to 22 out of 24, or 92%. Although the data also indicate thatin general, rejuvenation did not contribute to higher COS conversionperformance, it did contribute to higher CS₂ conversion performance.Overall the data indicate that both regenerated and rejuvenatedhydroprocessing catalysts in their native form can provide excellent COSconversion performance relative to the fresh tailgas competitivereference catalyst. The solvent extracted and hot nitrogen strippedversions of Catalyst F significantly underperformed the fresh tailgascompetitive reference catalyst. In fact, both displayed half or less ofthe COS conversion observed for the fresh commercial tailgas referencecatalyst at the highest temperature (300° C.) and conversion actuallyinflected to negative values, or net COS generation, at the lowesttemperature (220° C.), indicating these catalysts are highly unsuitablefor COS conversion.

As can be seen from FIG. 3, the regenerated and rejuvenatedhydroprocessing catalysts in their native form compare quite favorablywith the fresh tailgas competitive reference catalyst. To provide a morecomprehensive picture of how the performance affects the sulfur recoveryefficiency (SRE) impact by the catalyst, a combined metric for overallconversion of the sulfur in SO₂, CS₂, and COS was calculated. Theequation used to calculate this metric is reproduced in FIG. 4, whichalso provides a comparison (Table 3) of the overall sulfur conversionobtained using the thirteen catalysts. All nine of the regenerated andrejuvenated hydroprocessing catalysts in their native form outperformedthe fresh tailgas competitive reference catalyst at 240° C. and above.At the low temperature, 220° C., six of the regenerated and rejuvenatedcatalysts significantly outperformed the fresh tailgas competitivereference catalyst, while three were within 1%, a trivial difference.Therefore, practically speaking, the regenerated and rejuvenatedhydroprocessing catalysts in their native form performed as well orbetter than the fresh commercial tailgas reference catalyst. Overall,this comprehensive view of sulfur conversion performance indicates thatregenerated and rejuvenated hydroprocessing catalysts, if appliedcorrectly, can offer an excellent alternative to very well-establishedtailgas catalyst products in the market such as the fresh tailgascompetitive reference catalyst tested. The solvent extracted and hotnitrogen stripped versions of Catalyst F both significantlyunderperformed the fresh tailgas competitive reference catalyst. Thepoor performance results for the solvent extraction and hot nitrogenstripped versions of Catalyst F can be explained by the fact that thecoke deactivation of the spent catalyst is not eliminated by thesetreatments as it is with thermal oxidative regeneration. Regenerationtreatment is necessary to substantially remove the coke present on thecatalyst and enable a high performing catalyst for this application.

Example 2—“Stress Testing” at High Space Velocity (3,000 GHSV)

The performance of catalysts 1-4 and 13 described in Example 1 weretested using the same experimental set-up but under high space velocityconditions. The space velocity of the gas for the performance testconditions was 3,000 GHSV, equivalent to a residence time of 1.2seconds, and was intended to represent a “stress test” to furtherdifferentiate relative catalyst performance vs. the 1,200 GHSV testing.The performance tests occurred at three distinct temperature conditions:220° C., 250° C., and 280° C. At each condition, the temperature washeld for a time of 12 hours. Compositional analysis of the reactoreffluent was performed every 2 hours by gas chromatography. From thefeed and effluent gas analysis at each performance test condition, theconversion of SO₂, CS₂, and COS were determined. Table 4 (FIG. 5) andFIGS. 6-9 show the results of the testing at 3,000 GHSV.

FIG. 6 shows SO₂ conversion performance at 3000 GHSV using the fivecatalysts. Out of the twelve performance data points generated at eachcondition for the four regenerated and rejuvenated hydroprocessingcatalysts, only three performance data points fell below the freshtailgas competitive reference catalyst, with two of the threeunderperforming by less than 1%. The fact that nine out of the twelveperformance data points indicated superior performance shows that thehydroprocessing catalysts can be fit for the use of SO₂ hydrogenation inClaus tailgas hydrogenation service. Overall, conversion was still veryhigh (>97%) for all samples tested, above 220° C. At 220° C., three outof the four hydroprocessing catalysts showed higher performance than thefresh tailgas competitive reference.

FIG. 7 shows CS₂ conversion performance at 3000 GHSV using the fivecatalysts. Out of the twelve performance data points generated at eachcondition for the five regenerated and rejuvenated hydroprocessingcatalysts, all of them indicated superior performance compared to freshtailgas competitive reference catalyst. The fact that all twelve of datapoints indicated superior performance shows that the hydroprocessingcatalysts can be fit for the use of CS₂ hydrolysis in Claus tailgashydrogenation service. Not only did the hydroprocessing catalysts testedoutperform, they did so by a wide margin (>20%) across the board, a verysurprising finding. As with the testing at 1,200 GHSV outlined inExample 1, it is important to note that these results also suggest thatthe rejuvenation process enhances activity for CS₂ hydrolysis.

FIG. 8 shows COS conversion performance at 3000 GHSV using the fivecatalysts. Out of the twelve performance data points generated at eachcondition for the four regenerated and rejuvenated hydroprocessingcatalysts, only two performance data points fell below those of thefresh tailgas competitive reference catalyst. With ten out of the twelveperformance data points indicating superior performance, it is clearthat the hydroprocessing catalysts can be fit for the use of COShydrolysis in Claus tailgas hydrogenation service. It is worth notingthat at 250° C. and above, the hydroprocessing catalyst samples testedoutperformed the fresh tailgas competitive reference catalyst by about20%. Only at the 220° C. condition did the COS conversion for two of thefour hydroprocessing catalysts drop below that of the fresh tailgascompetitive reference catalyst. For overall tailgas hydrogenationperformance, the data indicate that both regenerated and rejuvenatedforms can provide good performance compared to the fresh tailgascompetitive reference catalyst. One interesting feature to note was thatthe Excel® Rejuvenated Catalyst A sample displayed a negativeconversion, or net formation, of COS at 220° C. This is likely becausethe COS hydrolysis pathway is kinetically limited for this catalyst,thus not allowing approach to the calculated equilibrium conversion andmeaning that COS can be formed faster than it is consumed by reaction.This is also indicated by the fact that conversion was about 62% at 220°C. and 1,200 GHSV (see Example 1) but at the higher space velocity (3000GHSV) in this example, the conversion decreased to −20%, or a netformation of 20%.

Overall, the regenerated and rejuvenated hydroprocessing catalystscompare favorably with the fresh tailgas competitive reference catalyst.FIG. 5 and FIG. 9 shows how these catalysts perform with respect tooverall sulfur recovery efficiency (SRE, see Equation of FIG. 4) at 3000GHSV. For the overall sulfur conversion performance, all the regeneratedand rejuvenated catalysts that were tested displayed equivalent orbetter performance than the fresh tailgas competitive referencecatalyst. Except for the Regenerated Catalyst A sample at 220° C., theoverall picture was one of substantial outperformance compared to freshtailgas competitive reference catalyst. These “stress test” resultsfurther confirm the findings from the realistic 1,200 GHSV testing inExample 1, namely, that regenerated and rejuvenated hydroprocessingcatalysts, when applied correctly, can offer an excellent alternative tovery well-established tailgas catalyst products in the market such asfresh tailgas competitive reference catalyst.

Example 3: Preparation of Regenerated 3.39 wt % Cobalt—16.57 wt %Molybdenum—Balance Alumina Catalyst

The following is a preparation procedure for making a catalyst with 3.39wt. % cobalt (as CoO) and 16.57 wt. % molybdenum (as MoO₃), with thebalance consisting of primarily alumina (Al₂O₃). The source of thecobalt and molybdenum metals came from a spent 2.5 mm trilobe CoMo onalumina hydroprocessing catalyst (See Catalyst C—Application 1 inTable 1) which contained 3.39% cobalt and 16.57% molybdenum asdetermined by XRF analysis. The hydroprocessing catalyst was regeneratedby a regeneration process, as described above in Example 1. In this way,the Regenerated Catalyst C—Application 1 sample which was performancetested under realistic tailgas conditions (see data in Table 2 and 3),was prepared.

While the invention herein disclosed has been described in terms ofspecific embodiments and applications thereof, numerous modificationsand variations could be made thereto by those skilled in the art withoutdeparting from the scope of the invention set forth in the claims.

Example 4: Preparation of Rejuvenated 3.50 wt % Nickel—15.86 wt %Molybdenum—Balance Alumina Catalyst

The following is a preparation procedure for making a catalyst with 3.50wt. % nickel (as NiO) and 15.86 wt. % molybdenum (as MoO₃), with thebalance consisting of primarily alumina (Al₂O₃). The source of thenickel and molybdenum metals came from a spent 2.5 mm trilobe NiMo onalumina hydroprocessing catalyst which contained 3.50% nickel and 15.86%molybdenum as determined by XRF analysis. The catalyst was prepared byPorocel's Excel® rejuvenation process as described in U.S. Pat. No.9,895,679. In this way, the Excel® Rejuvenated CommercialHydroprocessing Catalyst D (2.5 mm trilobe) sample which was performancetested under realistic tailgas conditions (see data in Table 2 and 3),was prepared.

While the invention herein disclosed has been described in terms ofspecific embodiments and applications thereof, numerous modificationsand variations could be made thereto by those skilled in the art withoutdeparting from the scope of the invention set forth in the claims.

What is claimed is:
 1. A method of treating a gas stream in a tailgastreating process, the method comprising: contacting the gas stream witha catalyst that was previously used in a hydrotreating process and thathas been reactivated by a reactivation process prior to contacting thegas stream in the tailgas treating process, wherein the gas streamcomprises one or more sulfur-containing species selected from the groupconsisting of elemental sulfur (S_(x)), sulfur dioxide (SO₂), carbonylsulfide (COS), and carbon disulfide (CS₂), and wherein contacting thegas stream with the reactivated catalyst in the presence of hydrogen(H₂) converts the one or more sulfur-containing species to hydrogensulfide (H₂S).
 2. The method of claim 1, wherein the hydrotreatingprocess is selected from the group consisting of petroleum hydrotreatingprocesses, hydrodesulfurization (HDS), hydrodenitrogenation (HDN),hydrogenation, hydrodemetallization (HDM), naphtha hydrotreating (NHT),diesel hydrotreating (DHT), kerosene hydrotreating (KHT), jet fuelhydrotreating (JHT), atmospheric gas oil hydrotreating, vacuum gas oil(VGO) hydrotreating, and fluid catalytic cracker (FCC) feedhydrotreating.
 3. The method of claim 1, wherein the catalyst comprisesone or more Group VIIIB metals and one or more Group VIB metalssupported on an inorganic oxide carrier material.
 4. The method of claim1, wherein the catalyst comprises cobalt and molybdenum supported onaluminum oxide.
 5. The method of claim 1, wherein the catalyst comprisesnickel and molybdenum supported on aluminum oxide.
 6. The method ofclaim 1, wherein the reactivation process comprises regeneration.
 7. Themethod of claim 6, wherein the regeneration comprises heating thecatalyst in an oxygen-containing atmosphere at a temperature of 300 to500° C. for a time of 30 minutes or more.
 8. The method of claim 6,wherein prior to the regeneration treatment, hydrocarbons are removedfrom the catalyst by solvent extraction or by contacting the catalystwith steam, natural gas combustion products, hydrogen or nitrogen at atemperature of 150 to 550° C.
 9. The method of claim 1, wherein thereactivation process comprises rejuvenation.
 10. The method of claim 9,wherein the rejuvenation comprises impregnating the catalyst with asolution containing a chelating agent and drying the catalyst at atemperature of 50° C. to 300° C.
 11. The method of claim 10, wherein thechelating agent is an organic acid.
 12. The method of claim 1, whereinthe reactivated catalyst is pre-sulfurized prior to contacting the gasstream in the tailgas treating process.
 13. The method of claim 1,wherein the reactivated catalyst is pre-sulfided prior to contacting thegas stream in the tailgas treating process.
 14. The method of claim 1,wherein the reactivated catalyst is resized, reshaped, and/orreformulated prior to contacting the gas stream in the tailgas treatingprocess.
 15. The method of claim 14, wherein the reactivated catalyst isresized by length grading the catalyst.
 16. The method of claim 14,wherein the resizing, reshaping, and/or reformulating comprises millingthe reactivated catalyst to a fine powder and then reforming thereactivated catalyst.
 17. The method of claim 14, wherein thereactivated catalyst is resized from having a diameter of 1.3 to 2.5 mmto having a diameter of 3 to 5 mm.
 18. The method of claim 1, whereincontacting the gas stream with the reactivated catalyst comprisescombining the reactivated catalyst with a second catalyst, wherein thesecond catalyst provides a lower pressure drop than the reactivatedcatalyst.
 19. The method of claim 1, wherein contacting the gas streamwith the reactivated catalyst comprises short loading the reactivatedcatalyst.
 20. The method of claim 1, wherein the reactivated catalystexhibits a pressure drop of 0.05 to 0.20 psi/ft, when sock-loaded andtested at 100 ft/min superficial velocity in ambient air.